Apparatus and method for identifying cable phase in a three-phase power distribution network

ABSTRACT

A line phase identification system and method identifies the phase of a power line at a remote unknown-phase line ( 160 ) in a three-phase power distribution network (100). The instantaneous phase of a known-phase line ( 150 ) is measured and saved each GPS second using a 1-pps time mark of a GPS receiver ( 660 ). The instantaneous phase at the unknown-phase line ( 160 ) is measured at a single GPS second using the 1-pps time mark of a GPS receiver ( 660 ) and compared to the phase measurement taken from the known-phase line ( 150 ) at the same GPS second. The differential phase between these simultaneously taken known and unknown instantaneous phases will be close to either 0, +120, or −120 degrees, thus identifying the line phase at the line under test ( 160 ).

TECHNICAL FIELD

[0001] The present invention relates to the field of three-phase powerdistribution networks. More specifically, the present invention relatesto the field of identifying the phase of a power line in a three-phasepower distribution network.

BACKGROUND ART

[0002] Electric power distribution networks are used by the electricutilities to deliver electricity from generating plants to customers.The actual distribution voltages will vary from country to country andfrom utility to utility within a given country. In a typical powerdistribution network in the U.S., three-phase power at a high voltage(e.g., 345 kilovolts phase-to-phase) is delivered to multipletransmission substations. At these transmission substations, thishigh-voltage power is stepped down to an intermediate three-phasevoltage (e.g., 69 kilovolts phase-to-phase). The intermediate-voltagethree-phase power from each transmission substation is then delivered tomultiple distribution substations. At the distribution substations, theintermediate-voltage is stepped down to a lower distribution voltage(e.g., 12.47 kilovolts phase-to-phase) and separated into threesingle-phase feeder lines (e.g., 7.2 kilovolts phase-to-ground). Each ofthese feeder lines branches into multiple circuits to power a pluralityof local pole-mounted or pad-mounted transformers that step the voltagedown to a final single-phase voltage of 120 and 240 volts for deliveryto the commercial and residential customers.

[0003] Ideally, the utilities try to initially design the feedercircuits such that the loads are balanced, i.e., the current loads oneach single-phase output of a three-phase transformer are equal.However, over time, as customers are added and removed, the loads oneach single-phase output may change and become unbalanced. To re-balancethe loads, some of the branch circuits are typically moved from a moreheavily loaded phase to a more lightly loaded phase.

[0004] To re-balance the loading, the phase of each line in adistribution cabinet must be accurately known. Otherwise, a line may beerroneously removed from a more lightly loaded phase and placed on amore heavily loaded phase. If this happens, the procedure will have tobe repeated, which will cause a second disruption in service to allcustomers on the branch being re-phased. In the worst case, adding agreater load to the more heavily loaded phase may cause a substationfuse to blow, resulting in a power outage for all customers on theoverloaded phase.

[0005] Currently, to accurately identify the phase of a particularfeeder branch, utility company personnel must physically trace a linerun back through various distribution cabinets until they reach a pointin the distribution network at which the phase is definitely known. Thiscan be a time consuming, labor-intensive process.

[0006] Various devices and methods have been described to assist in thephase identification of lines. Bouvrette, U.S. Pat. No. 4,626,622,proposes using modems and telephone lines to establish a communicationlink. A signal associated with the phase at a point in the network wherethe phase of the line is known (the reference line) is transmitted overthe communication link to a point in the network where the phase of theline is not known (the line under test). Difficulties arise with thismethodology in that delays in the communication link may severely affectthe accuracy of the phase measurement.

[0007] Pomatto, U.S. Pat. No. 5,510,700, proposes a similar scheme tothat of Bouvrette save that the communication link uses radiotransmissions to eliminate communication-link delay problems. However,both Bouvrette and Pomatto require calibration procedures and specialtraining for their techniques to be used effectively.

[0008] Hao, U.S. Pat. No. 6,130,531, proposes a method and apparatus tocompare phases between electric power system substations in real time.His method is similar to that of Bouvrette and Pomatto except that Haouses a time base locked to Global Positioning System (GPS) time at boththe reference line and the line under test to eliminate delay andsynchronization problems.

[0009] Finally, a phase identification instrument is currently availablethat, like Hao, uses GPS receivers at both the reference line and theline under test to eliminate delay and synchronization problems, and,like Bouvrette, uses a cellular data communication link to convey thephase of the reference line to the line under test location. Thisinstrument transmits the instantaneous phase of the reference line onceeach GPS second. The instantaneous phase of the line under test ismeasured at a given second, then compared to the phase of the referenceline for that same second. All communication and readings are performedin the same one-second interval. This necessitates communication delayis less than one second.

[0010] In all these approaches, a pre-established real-timecommunication link is required. That is, a communication link needs beestablished and active at the time the phase of the line under test ismeasured. This renders these approaches unusable wherever and wheneverthe communication link cannot be established. Also, since the phase ofthe line under test is determined for each measurement, the measuringapparatus must be retrieved after each test. This precludes the abilityto make several different tests before accessing the apparatus, e.g.,measuring the phases of several different overhead lines in a substationbefore lowering the “hot stick” to which the apparatus is attached.

[0011] Accordingly, it is the object of the present invention to providea new and improved apparatus and method for the identification of linephase of a power line in a three-phase power distribution network. Theapparatus and method do not require a pre-established real-timecommunication link, do not suffer from communication delay andsynchronization difficulties, do not require calibration procedures tobe performed, and do not require special training on the part of theoperator.

DISCLOSURE OF INVENTION

[0012] Briefly, to achieve the desired object of the present invention,Global Positioning System (GPS) receivers are used at both the known andunknown phase locations in the power distribution network totime-correlate phase information, thereby identifying the phase of theline in question.

[0013] Specifically, using the 1 pps (one pulse per second) GPS signal,phase information for the known phase will be recorded at each GPSsecond and entered into a computer. A worker at the unknown phaselocation will simultaneously also record the line phase information at aparticular 1 pps GPS second on a phase identification meter that willconvert the recorded time and phase to a short alpha or numericsequence. The worker will then give that sequence to the dispatcher. Thedispatcher will determine the phase by entering the sequence receivedfrom the worker into the computer. The dispatcher will then relay theline phase designation back to the worker.

[0014] Alternatively, the worker can simply write down or otherwiserecord the sequence and relate it to the dispatcher at a later time. Inboth cases, no real time communication link is required.

[0015] In this way, the worker determines the line phase by taking asimple meter measurement in much the same way voltage and currentmeasurements are taken. Therefore, no special procedures or training isrequired on the part of the worker.

BRIEF DESCRIPTION OF DRAWINGS

[0016] A more complete understanding of the present invention may bederived by referring to the detailed description and claims whenconsidered in connection with the Figures, wherein:

[0017]FIG. 1 is a schematic diagram of a typical power distributionnetwork in accordance with a preferred embodiment of the presentinvention;

[0018]FIG. 2 is a phasor diagram of voltage phase relationships in athree-phase power network in accordance with a preferred embodiment ofthe present invention;

[0019] FIG. is a voltage versus time diagram of voltage phaserelationships in a three-phase power network in accordance with apreferred embodiment of the present invention;

[0020]FIG. 4 is a schematic diagram of the equivalent circuit of atransformer referred to its secondary in accordance with a preferredembodiment of the present invention;

[0021]FIG. 5 is a phasor diagram of the circuit of FIG. 4 in accordancewith a preferred embodiment of the present invention;

[0022]FIG. 6 is a conceptual block diagram of a phase identificationmeter in accordance with a preferred embodiment of the presentinvention;

[0023]FIG. 7 is a phasor diagram of secondary voltage phaserelationships in a three-phase power network for wye- anddelta-connected transformers in accordance with a preferred embodimentof the present invention;

[0024]FIG. 8 is a schematic of a wye-connected transformer in accordancewith a preferred embodiment of the present invention; and

[0025]FIG. 9 is a schematic of a delta-connected transformer inaccordance with a preferred embodiment of the present invention.

BEST MODE FOR CARRYING OUT THE INVENTION

[0026] This discussion is concerned with power distribution at both 60and 50 Hertz (Hz). To avoid confusion, all references to parameters of50-Hz systems will be bracketed and will follow the same parameters for60-Hz systems. For example, the phrase “for power at 60 [50] Hz, eachcycle takes 16.67 [20.0] milliseconds” indicates that in a 60-Hz systemeach cycle takes 16.67 milliseconds, while in a 50-Hz system each cycletakes 20.0 milliseconds.

[0027] Also, it will be noted that in the preferred embodimentsdiscussed herein mention is made of 120-volt and 240-volt commercial andresidential voltages. Those skilled in the art will appreciate thatthese voltages are standard in the U.S. The use of other voltages, suchas the 230-volt E.U. standard, does not depart from the spirit of thepresent invention.

[0028] The goal of the present invention is to provide the utilityworker with an easy to use phase identification apparatus and method foridentifying the phase of a line in a three-phase power distributionnetwork 100.

[0029]FIG. 1 is a schematic diagram of a typical power distributionnetwork 100 in accordance with a preferred embodiment of the presentinvention. The following discussion refers to FIG. 1.

[0030] In power distribution network 100, three-phase power lines 105 at345 kilovolts feed a series of transmission substation (TS) transformers110 spread out over a large geographical area. The 69-kilovolt outputs115 of TS transformers 110 are connected to a series of distributionsubstation (DS) transformers 120 situated over a smaller geographicalarea. The 7.2-kilovolt phase-to-ground (12.5-kilovolt phase-to-phase)phase-A feeder output 125 of a DS transformer 120 powers a localdistribution network, which contains a number of pole-mounted orpad-mounted (PM) transformers 140 that are used to provide the final120/240-volt power to the commercial or residential customers. In thesame manner, phase-B feeder output 130 of transformer 120 powers anotherlocal distribution network, while phase-C feeder output 135 powers athird local network.

[0031] At some location in the power distribution network 100, a givenPM transformer 140 is used to provide a low-voltage input reference ofphase A, B, or C to a permanently attached reference phaseidentification meter 145 (hereinafter reference meter 145). Thisreference meter 145 most likely will be situated in the dispatchfacility. Reference meter 145 is connected to an output 150 of given PMtransformer 140, i.e., to a reference line 150 having a known phase. Thepurpose of reference meter 145 is to provide a reference of phase A, B,or C that can be used to determine the unknown phase of a line at anyother location in network 100. A worker at a remote location usesanother phase identification meter 155 (hereinafter test meter 155) tomomentarily probe the voltage on the line under test 160, i.e., the linewhose phase is to be determined.

[0032]FIGS. 2 and 3 depict line phase relationships in three-phase powernetwork 100 as a phasor diagram (FIG. 2) and a voltage versus timediagram (FIG. 3) in accordance with a preferred embodiment of thepresent invention. The following discussion refers to FIGS. 1, 2, and 3.

[0033] Phasor diagram 200 illustrates the phase relationship betweenphases A, B, and C in three-phase power distribution network 100. Phasordiagram 200 represents phase A as phasor 205 at 0 degrees, phase B asphasor 210 at 120 degrees, and phase C as phasor 215 at 240 degrees. In60-Hz [50-Hz] power network 100, the entire phase diagram rotates at arate of 60 [50] revolutions per second but the phase differences betweenadjacent phases A, B, and C remains a constant 120 degrees. Eachrevolution of the phase diagram represents 360 degrees of phase rotationby the voltage phasors.

[0034] Because phase is rotational, each phase may be said to both leadand lag each other phase. Phase A leads phase B by 120 degrees, leadsphase C by 240 degrees, lags phase C by 120 degrees, and lags phase B by240 degrees. Phase B leads phase C by 120 degrees, leads phase A by 240degrees, lags phase A by 120 degrees, and lags phase C by 240 degrees.And phase C leads phase A by 120 degrees, leads phase B by 240 degrees,lags phase B by 120 degrees, and lags phase A by 240 degrees. This maybe clearly seen in phasor diagram 200.

[0035] Voltage versus time diagram 300 depicts the same phaserelationships as phasor diagram 200. To complete a single 360-degreecycle of phase rotation, the voltage of each phase starts at zero volts,peaks in the positive direction, returns to zero volts, peaks in thenegative direction, and again returns to zero volts. Phase A, B, and Care represented by voltage waveforms 305, 310, and 315 respectively.

[0036] For power at 60 [50] Hz, each cycle takes 16.67 [20.00]milliseconds to complete a 360-degree cycle. This is equivalent to 46.3[55.56] microseconds per degree or 5.55 [6.67] milliseconds for 120degrees. Therefore, phases A, B, and C are separated in time by 5.55[6.67] milliseconds.

[0037] Since the frequency of 60-Hz [50-Hz] power distribution network100 is so low, there is very little voltage phase shift between twopoints on the same phase anywhere in network 100. That is, if one wereto observe the voltage waveforms of phase A at widely separated pointsin network 100, all voltages would pass through a predetermined voltagein a predetermined direction at substantially the same time. In thepreferred embodiment, the predetermined voltage is zero volts and thepredetermined direction is rising, i.e., from negative to positive. Thatis, all voltages would rise though zero volts at substantially the sametime.

[0038] In the present invention, the phase of the voltage waveforms attwo widely separated points in power distribution network 100 areobserved and compared at substantially the same instant. Desirably, thisis accomplished by using standardized precision time signals, such asthose from the Global Positioning System (GPS). The use of suchprecision time signals allows all operators to have a precise timecorrelation so that an instantaneous phase measurement can be taken atdifferent locations in network 100 at substantially the same time. Thetime marks in FIG. 3 illustrate the method by which the unknown phase online under test 160 can be determined.

[0039] Those skilled in the art will appreciate that the phrase“instantaneous phase” is taken to mean the phase of each samplesynchronized to start at substantially the same instant. The absolutetime require to take each sample is irrelevant to this discussion. Itwill also be appreciated that a determination of phase may be performedin any of numerous ways well known to those skilled in the art,including, but not limited to, the time duration methodology discussedherein.

[0040] Assume that a timer is started at some instant of time t0 (astart time 320). At reference line 150 (assumed here to be connected tophase A), the timer is stopped when phase A voltage rises through zerovolts. This represents a time interval ta 325 since time t0. Since thetime difference between phases is 5.55 [6.67] milliseconds, timeinterval tb 330 of phase B and time interval tc 335 of phase C can becalculated directly without having to actually measure the voltage onphases B and C.

[0041] At line under test 160, the point of unknown phase, a similartimer is also started at the same instant of time t0 (start time 320).The timer is stopped when the voltage rises through zero volts. Thisrepresents a time interval tx (not shown). The time interval tx will besubstantially equal to one of the time intervals ta, tb, or tc,depending on whether the phase of the line under test is A, B, or C,respectively. Therefore, the unknown phase of line under test 160 may bedetermined by comparing the time interval of the test meter 155 to thatof reference meter 145.

[0042] There is no need for the unknown phase to be computed during thesame 1-second interval in which the data is gathered. If start time t0320 is recorded, time interval ta 325, tb 330, or tc 335 of referencemeter 145 is recorded, and the time interval tx of test meter 155 isrecorded, then the unknown phase of line under test 160 may be computedat any time in the future, even hours or days later. This method issuperior to the prior art mentioned earlier because a real-timecommunication link for the transmission of reference line phase datafrom the reference site to the remote site is not required. By notrequiring a real-time communication link, all problems associated withsuch a link (e.g., delay, synchronization, interference, obstruction,etc.) are avoided.

[0043] In the preferred embodiment, start time to 320 is determined bythe GPS time. That is, start time t0 320 is preferably equal to or afixed delay after a GPS time 1-second tick. Those skilled in the artwill appreciate, however, that there are methodologies other than theGPS that may be used to establish start time t0 320. The use of one ofthese other methodologies does not depart from the spirit of the presentinvention.

[0044] The GPS allows phase data to be gathered and recorded at bothreference line 150 and line under test 160 at substantially the samestart time t0 320. In the preferred embodiment, repetitive triggersignals based upon the GPS 1-second ticks are received by referencemeter 145. Reference phase data (phase data of reference line 150) isobtained for each trigger signal and recorded by reference meter 145.This database of reference phase data is then retrieved at a convenienttime and in a convenient manner. A worker gathers test phase data byperforming a phase test of line under test 160 using test meter 155.This information is obtained and recorded in the field, then latercompared with the stored reference phase data. As long as referencemeter 145 recorded reference phase data at a time that matched the timerecorded on test meter 155 for test phase data, the phase of line undertest 160 can be determined.

[0045] By extension, if one or more workers (using one or more testmeters 155) gather test phase data at multiple lines under test 160,that test phase data is recorded in the field and later compared withthe stored reference phase data. As long as reference meter 145 recordedreference phase data at times that matched at least one of the timesrecorded on test meter 155 for each test phase data, the phases of thelines under test 160 can be determined.

[0046] For in-field determination of the phase of line under test 160, afield worker performs a phase test. That is, the field worker connectstest meter 155 to line under test 160 and gathers test phase data. Thefield worker calls a dispatcher or other worker at the site of referencemeter 145 and relays the test phase data. The test phase data containstime stamp for start time t0 320 and a test interval (the phase timeinterval tx for line under test 160). The dispatcher enters the testphase data into reference meter 145, computer 165, or other instrument.The test phase data is compared to the stored reference phase data forthe same start time to 320, and the unknown phase of line under test 160is determined. The dispatcher then relays this phase information to thefield worker, if required.

[0047] GPS receivers typically output a time mark at 1-second intervals.These time marks are locked to GPS time in seconds. This providesconvenient time frames for reference meter 145 to take and recordreference phase data. Test meter 155 used by the worker also collectstest phase data at the same 1-second time mark as determined by its GPSreceiver. The dispatcher's computer 165 or other instrument searchesback through the recorded reference phase data to find the datacollected at the same GPS second as the test phase data to determine theunknown phase.

[0048] Once both the reference and the test phase data have beengathered, the determination of phase of line under test 160 is readilymade. Assume, for the sake of discussion, that reference meter 145 isconnected to phase B, and that reference phase data indicates that thereference interval (the time interval from start time to 320 to stoptime tb 330) is 7.04 [8.45] milliseconds (152 degrees). Then, if thetest phase data indicates that the test interval (the time interval fromstart time t0 320 to stop time tx) is 1.49 [1.78] milliseconds (32degrees), then the phase of line under test 160 leads the phase ofreference line 150 by 5.55 [6.67] milliseconds (120 degrees). The phaseof line under test must therefore be phase A.

[0049] Note that since phases A, B, and C are separated by 120 degrees,it is not necessary to measure phase precisely to identify the unknownphase. If the unknown phase is within ±59 degrees of one of thereference phases, the unknown phase will be accurately determined.Electrical power at 60 [50] Hz propagates through distribution network100 at slightly less than the speed of light. It therefore requiresapproximately 8.6 [10.4] miles (13.8 [16.7] kilometers) to obtain 1degree of phase shift due to propagation. Therefore, a service radiusaround reference meter 150 of up to 120 [145] miles (193 [233]kilometers) is attainable. Assuming a 10-degree error budget, theservice radius is at least 80 [97] miles (129 [156] kilometers).

[0050] A time uncertainty of 100 nanoseconds represents approximately0.00216 [0.0018] degree of phase shift at 60 [50] Hz. GPS receiversdetermine time much more accurate than 100 nanoseconds. Therefore, GPStime uncertainty is simply not an issue in this application.

[0051]FIGS. 4 and 5 are a schematic diagram of an equivalent circuit 400of a transformer and a phasor diagram 500 of circuit 400 in accordancewith a preferred embodiment of the present invention. The followingdiscussion refers to FIGS. 1, 4, and 5.

[0052] Another potential source of phase shift in network 100 (otherthan from power factor correction circuits) is the voltage phase shiftthat can occur in a transformer. In transformer equivalent circuit 400,the primary voltage Vp at an input terminal 410 produces secondaryvoltage Vs at an output terminal 425. A loss-free transformer 405reduces the primary voltage Vp by the factor “a” based on the primary tosecondary turns ratio. All transformer losses, referred to the secondaryhere, further reduce voltage Vs and cause its phase to be shifted withrespect to primary voltage Vp. The secondary winding of transformer 405has an inherent resistance Re and an inherent reactance Xe. The voltagedrop due to transformer resistance Re is represented by current passingthrough resistor 415. The voltage drop due to transformer reactance Xeis represented by current passing through inductor 420.

[0053] Phasor diagram 500 has been greatly exaggerated to betterillustrate how phase shift through a transformer occurs. When a laggingpower factor load 430 is placed on the output of the transformer,secondary current Is, represented by phasor 505, flows out of phase withthe secondary voltage Vs, represented by phasor 510 as is well known bythose skilled in the art. The power factor phase shift 515 is determinedby the power factor of the load 430.

[0054] The voltage drop due to Re is in phase with secondary current Isand is represented by phasor 520. The voltage drop due to Xe is 90degrees out of phase with secondary current Is and is represented byphasor 525. The phasor addition of these voltage drops to secondaryvoltage Vs equals the loss-free turns ratio voltage Vp/a represented byphasor 530. Since no phase shift occurs through loss-free transformer405, transformer phase shift 535 represents the voltage phase shift dueto the transformer.

[0055] The phase shift through a transformer depends on the magnitudeand power factor of the load current. However, in modern powerdistribution transformers, power losses are only a few percent so theresistive and reactive voltage drops are very small compared to theirprimary and secondary voltages. Therefore, voltage phase shift throughthe transformer is typically less than ±5 degrees.

[0056] The total voltage phase-error budget is ±59 degrees. The phaseuncertainties due to propagation and GPS time tagging are less than ±10degrees as was explained earlier. Therefore, nearly ±50 degrees oftransformer phase shift can be tolerated before the accuracy ofidentifying the unknown phase is compromised. This large allowable phaseuncertainty allows reference meter 145 and test meter 155 to beseparated by many transformers. That is, phase A in network 100 isessentially the same everywhere in network 100, so reference meter 145can be placed almost anywhere, including on the dispatcher's desk andplugged into a wall socket. The wall socket does not even have to bephase A. As long as reference meter 145 knows which phase is thereference phase, the phase identification method described here willwork.

[0057]FIG. 6 is a conceptual block diagram of a phase identificationmeter 600 in accordance with a preferred embodiment of the presentinvention. The following discussion refers to FIGS. 1 and 6.

[0058] Test meter 600 (test meter 155 in FIG. 1) may be used directly orattached to the end of a hot stick. A voltage probe 605 of test meter600 is placed against line under test 610 (line under test 160 in FIG.1). Line under test 610 is modeled as an AC voltage with respect toground 615 by voltage source 620. Test meter 600 is connected to ground615 through a grounding wire 625.

[0059] A voltage divider between line under test 610 and ground 615 isused. The voltage divider is formed of a high value line resistor 630,on the order of 10 megohms, in series with a low value ground resistor635, on the order of 1 kilohm. Line resistor 630 connects to line undertest 610 and ground resistor 635 connects to ground 615. The junction ofline resistor 630 and ground resistor 635 connects to the input of ananalog to digital (A/D) converter 640. By using a sensitive A/Dconverter 640, only a few millivolts of voltage from line under test 610need be developed across ground resistor 635. Back to backvoltage-clamping diodes 645 may be used to protect A/D converter 640from damage due in the event of an overvoltage.

[0060] The heart of test meter 600 is a processor 650. Processor 650contains a memory and computing resources. An interval timer 655 isconfigured to control and be controlled by processor 650. Interval timer655 may be incorporated into processor 650. A/D converter 640 convertsthe line-under-test voltage into a digital signal. A 1-pulse-per-second(1-pps) signal is received by a GPS receiver 660, which then commandsinterval timer 655 to start. This is time t0. A transition of apredetermined voltage in a predetermined direction (a transition of zerovolts from negative to positive in the preferred embodiment) of the lineunder test 160, as measured by A/D converter 640, causes processor 650to stop interval timer 655. This is time tx. Processor 650 then recordsthe time interval between t0 and tx, along with the GPS time 320 (FIG.3) that initiated timer 655.

[0061] A measurement algorithm is programmed into processor 650 toensure that only good measurement data is recorded and displayed. Forexample, after test probe 605 contacts line under test 610, test meter600 may wait until the amplitude of the voltage across ground resistor635 reaches a predetermined value before initiating the phase test. Testmeter 600 may then perform phase tests at more than one GPS second andconfirm that successive measurements produce similar test intervalsbased on the frequency of line under test 610. At 60 [50] Hz, exactly 60[50] cycles occur each GPS second so that all test intervals should beidentical. However, the power line frequency in power distributionnetwork 100 may randomly vary from exactly 60 [50] Hz by a small amount(usually a few tenths of a percent or less). As long as successive testintervals are within the assumed tolerance, test phase data will berecorded and displayed, along with an indication to the worker that themeasurement is completed.

[0062] To guard against loss of the 1-pps GPS signal, a crystaloscillator 665 may be locked to GPS receiver 660. Crystal oscillator 665provides processor 650 with an accurate clock frequency so as tomaintain the 1-pps signal during periods of GPS signal outages. Thisallows test meter 600 to be used inside cabinets or in other areas whichmay block reception of the GPS signal. A typical crystal oscillator 665has a short-term accuracy on the order of 1 part per million (1 ppm).Since the phase of a 60 [50] Hz power line voltage rotates 1 degree per46.3 [55.6] microseconds, it takes 46.3 [55.6] seconds for a clock thatis in error by 1 ppm to accumulate 1 degree of phase uncertainty. For a10-degree error budget, GPS receiver 660 could lose lock for 7.7 [9.3]minutes. Therefore, once GPS lock is obtained in a clear area, testmeter 600 may be moved to a shielded area to obtain the phasemeasurement.

[0063] Other resources contained in the test meter 600 are display 670,user controls 675, non-volatile memory 680, battery 685, andinput-output port 690. Display 670 may be a typical LCD meter display todisplay the phase information to the worker. User controls 675 includethe on-off switch and any other buttons required to activate variousfeatures built into test meter 600. Battery 685 allows test meter 600 tooperate independent of external power. Non-volatile memory 680 allowsmeasurement data to be retained after test meter 600 is turned off.Input-output port 690 allows measurement information to be downloaded tocomputer 165.

[0064] It is anticipated that a mode will be offered in which GPS timeis designated in terms of the number of seconds since the last GPS hour.That is, the number would range from 1 second to 3600 seconds. Also, theinterval timer count could be quantified to increments of 1 degree. Thatis, the time duration between a GPS second and the first power linevoltage negative to positive zero crossing would range between 1 and 360degrees.

[0065] To make the phase data as short as possible, a single sequencecould be used in which a number between 1 and 360 represents the phaseinterval collected during the first GPS second. A number between 361 and720 represents the phase interval collected during the second GPSsecond, and so on. The largest possible number in this scheme would beequal to 3600 seconds times 360 degrees, or 1,296,000. This number couldbe expressed alphabetically (i.e., to base 26) where “A” equals 1, “B”equals 2, “Z” equals 26, “AA” equals 27, and so on to “BUSDD” equals1,296,000. In this way, the largest hourly number could be representedusing only five letters.

[0066] By extension, alphabetic encoding for a whole day wouldincorporate 3600 seconds per hour over 24 hours per day, or 86,400seconds. This scheme would produce a largest possible number of 86,400seconds times 360 degrees, which equals 31,104,000 or “BPAQKH”. Thelargest daily number could therefore be represented using only sixletters.

[0067] Reducing the phase data to only five or six letters minimizes thetime it takes the worker to verbally communicate the sequence to thedispatcher and minimizes the time it takes the dispatcher to enter thesequence into reference meter 145 or computer 165. It also increasestranscription accuracy in that the phonetic alphabet can be used toeliminate misunderstood letters or numbers. For example, the sequence“MHE” would be communicated phonetically as “Mike-Hotel-Echo.”

[0068] Reference meter 145 (reference meter 695 in FIG. 6) issubstantially identical to test meter 600 and operates in essentiallythe same manner. For reference meter 145, line under test 610 isreference line 150. Reference meter 145 will likely be “hard wired” toreference line 150, most likely through a conventional wall outlet. Thevoltage divider (series resistors 630 and 635) used in test meter 600may be replaced by a step-down transformer (not shown). This is not arequirement of the present invention, however, and the use of such atransformer does not depart from the spirit of the present invention.

[0069] Reference meter 145 may also have more computing power and alarger memory, thereby enabling the storage of a multiplicity ofreference phase data. Reference meter 145 and computer 165 may togetherform an integrated unit. In this case, reference meter 145 would have akeyboard to enter the test phase data obtained from the worker.Conversely, reference meter 145 and computer 165 may be separate units.Reference meter 145 may transfer all reference phase data to computer165 in real time or upon demand. If so, a software program running oncomputer 165 might handle all phase data storage andidentification-functions.

[0070] In a large metropolitan area, multiple reference meters 145 mightbe used at various locations for redundancy and reliability crosschecking. Also, if it is found that a significant phase shift occurs incertain branches due to power-factor correction circuits or othercauses, that information can be entered into a database for referencemeter 145. To take those phase shifts into account, the dispatcher wouldhave to enter information identifying the branch circuit of line undertest 160 along with the unknown phase data. Computer 165 would thenremove the known phase offset in making the determination of the unknownphase on that branch circuit.

[0071]FIG. 7 is a phasor diagram 700 of secondary voltage phaserelationships in a three-phase power network for wye- anddelta-connected transformers, and FIGS. 8 and 9 are schematics of awye-connected transformer 800 and a delta-connected transformer 900 inaccordance with a preferred embodiment of the present invention. Thefollowing discussion refers to FIGS. 1, 7, 8, and 9.

[0072] Relative phase measurements taken on the phase A, B, or C primaryvoltages will always be close to one of three reference phase angleswhich are separated by 120 degrees. However, relative phase measurementstaken on secondary voltages can be separated by only 30 degrees. Phasordiagram 700 represents the twelve different secondary phases that can beobtained on wye and delta connected transformers.

[0073] The most common transformer connection in power distributionnetwork 100 is the four-wire wye arrangement depicted in schematic 800.In a wye configuration, three-phase power is transported using a wirefor each of the three phases A, B, and C, plus a fourth center-connectedground wire. In a wye arrangement, therefore, the primary side of eachsingle-phase PM transformer is connected between one of the threeprimary phases and ground. A secondary winding having a grounded centertap supplies 120 and 240 volts to the commercial or residentialcustomer. Because of the center-tapped ground, only one of the 120-voltoutputs is in phase with the primary winding phase. The other 120-voltoutput is 180 degrees out of phase with the primary winding phase.

[0074] Referring to phasor diagram 700 and wye-connected transformer800, the primary winding 805 is connected between phase A and ground(phasor 705). One 120-volt output 810 (phasor 710) is in phase withprimary phase A, and the other 120-volt secondary output 815 (phasor715) is out of phase with primary phase A. Therefore, when test meter155 is applied to secondary voltages derived from phase A ofwye-connected transformer 800, the measured phase will be either 0 or180 degrees with respect to phase A. In a similar manner, for secondaryvoltages derived from phase B, the measured phase will be either 120 or300 degrees, and for secondary voltages derived from phase C, themeasured phase will be either 240 or 60 degrees.

[0075] An alternative transformer connection in power distributionnetwork 100 is the three-wire delta arrangement depicted in schematic900. In a delta configuration, three-phase power is transported using awire for each of the three phases A, B, and C without a center-connectedground wire. In a delta arrangement, therefore, the primary side of eachsingle-phase PM transformer is connected between two of the threeprimary phases, i.e., between phases A and B, phases B and C, or betweenphases C and A. Again, a secondary winding having a grounded center tapsupplies 120 and 240 volts to the commercial or residential customer.Because of the center-tapped ground, only one of the 120-volt outputs isin phase with the primary winding phase. The other 120-volt output is180 degrees out of phase with the primary winding phase.

[0076] Referring to phasor diagram 700 and delta-connected transformer900, the primary winding 905 is connected between phases A and B (phasor720). One 120-volt output 910 (phasor 725) is in phase with the primarywinding, and the other 120-volt secondary output 915 (phasor 730) is outof phase with the primary winding. Therefore, when test meter 155 isapplied to secondary voltages derived from phases A and B ofdelta-connected transformer 900, the measured phase will be either 150or 330 degrees with respect to phase A. In a similar manner, forsecondary voltages derived from phases B and C, the measured phase willbe either 270 or 90 degrees, and for secondary voltages derived fromphase C and A, the measured phase will be either 30 or 210 degrees.

[0077] Using test meter 155 on the outputs of wye-connected anddelta-connected transformers reduces the total phase error budget from±59 degrees to ±14 degrees. However, phase measurement tests made atwidely separated points on an actual power distribution network 100indicate that actual phase errors are much less than 14 degrees (theywere actually less than 5 degrees). Identifying line phase by measuringsecondary voltages is preferable by utilities to measuring primaryvoltages because it can be performed by personnel that are nothigh-voltage certified. An accessory attachment may be supplied with thephase identification meter to allow it to be simply plugged into anycommercial or residential wall socket to determine which primary phasepowers the facility.

[0078] Although the preferred embodiments of the invention have beenillustrated and described in detail, it will be readily apparent tothose skilled in the art that various modifications may be made thereinwithout departing from the spirit of the invention. This is especiallytrue in the area of user features.

[0079] For example, to speed up measurements on a series of overheadlines, test phase data from multiple phase test may be automaticallystored in test meter 155. Each new phase test would be initiated upondetection of new power line voltage that occurs a few seconds after theprevious power line voltage terminates. This feature would allow theworker to perform phase tests on a number of high overhead lines withouthaving to retrieve test meter 155 after each phase test.

[0080] It is also possible to capacitively couple probe 605 of testmeter 600 to line under test 610, instead of actually touching barewire, if the actual or estimated phase shift is accounted for. Thisfeature would allow test meter 600 to be used on insulated lines.

[0081] To limit maximum propagation phase error, test meters 600 couldbe programmed to only operate inside a designated service area. Locationcoordinates from GPS receivers 660 could be compared to a map programmedinto the processors 650 of each meter 600 to determine if that meter 600was inside the service area.

[0082] Many different ways of communicating the test phase data fromtest meter 155 to reference meter 145 or computer 165 are possible. Thetest phase data could be called in using terrestrial, cellular, or otherradio telephony, (e.g., a landline telephone, a cellular telephone, or autility radio) over a voice link. A modem or other computer could beused to send or E-mail the test phase data over a data link. The testphase data could be simply written down and delivered by courier, mail,or personally by the worker. The test phase data could be recordedwithin test meter 155 and downloaded to computer 165 at the end of thework shift. It will be understood that the use of any given methodologyto convey test phase data from test meter 155 to reference meter 145 orcomputer 165 does not depart from the spirit of the present invention.

[0083] Alternatively, one or more reference phase data could bedelivered to the test location and the unknown line phase determinedusing either test meter 155 or a test-location computer. Again, manydifferent ways of communicating the reference phase data to test meter155 or the test location computer are possible. The test locationcomputer could query the reference location computer 165 for therequired reference phase data or it could automatically receive andstore all new reference phase data as they became available. Acollection of the most current (last minute) reference phase data couldbe continuously broadcast to a receiver within test meter 155 and theunknown line phase determined automatically using test meter 155. Thebroadcast could be via FM subcarrier on a local FM station or satellite.

[0084] Because the phase data (the start time identifications and thephase measurement intervals) are delivered to computer 165 (which may beincorporated into either reference meter 145 or test meter 155),computer 165 lends itself to the development of a database containingthe phase data, especially the reference phase data. With such areference database, upon the arrival of test phase data, computer 165would then retrieve from the database the reference phase data havingthe same start time identification for computation of the unknown linephase (the phase of line under test 160).

[0085] Additionally, if the test phase data also contains anidentification of line under test 160 (i.e., a branch and/or circuitnumber uniquely identifying line under test 160), then the database maybe expanded (or another database may be created) to contain theidentification and phase of each line under test 160. This databasewould normally be filled using survey techniques. The existence of agiven line under test 160 in this database would preclude the necessityof future phase testing of that line.

[0086] In all these techniques, it is important to understand that areal time communication link is not required. As long as the referencemeter data is saved, the time period, between obtaining the test meterphase identification sequence and comparing it to the reference meterdata, could be hours, days, weeks, or months.

[0087] Although the preferred embodiments of the invention have beenillustrated and described in detail, it will be readily apparent tothose skilled in the art that various modifications may be made thereinwithout departing from the spirit of the invention or from the scope ofthe appended claims.

What is claimed is:
 1. An apparatus for identifying a phase of a powerline in a three-phase power distribution network (100), said apparatuscomprising: a reference phase identification meter (145,695) coupled toa reference line (150) at a first location in said network (100) andconfigured to gather reference phase data relative to said referenceline (150) at a predetermined time (320); a test phase identificationmeter (155,600) coupled to a line under test (160,610) at a secondlocation in said network (100) and configured to gather test phase datarelative to said line under test (160,610) at said predetermined time(320); and a computer (165) configured to establish communication withsaid test phase identification meter (155) after said test phaseidentification meter (155) has gathered said test phase data, configuredto receive said test phase data from said test phase identificationmeter (155), and configured to identify a phase of said second line(160) in response to said test phase data from said test phaseidentification meter (155) and said reference phase data from saidreference phase identification meter (145).
 2. An apparatus as claimedin claim 1 wherein said reference phase identification meter (695)comprises: a processor (650) configured to gather said reference phasedata; a receiver (660) coupled to said processor (650) and configured tocause said processor (650) to start gathering said reference phase dataat said predetermined time; and an analog to digital (A/D) converter(640) coupled between said reference line (150) and said processor(650), and configured to cause said processor (650) to stop gatheringsaid reference phase data.
 3. An apparatus as claimed in claim 1 whereinsaid test phase identification meter (600) comprises: an analog todigital (A/D) converter (640) coupled to said line under test (610); aprocessor (650) coupled to and configured to control said A/D converter(640); a timer (655) coupled to said processor (650) and configured tobe controlled by said A/D converter (640) through said processor (650);and a receiver (660) coupled to said processor (650) and configured tocontrol said timer (655).
 4. An apparatus as claimed in claim 3 whereinsaid receiver (660) is configured to synchronize said timer (655) to atime signal.
 5. An apparatus as claimed in claim 3 wherein: saidreceiver (660) is configured to cause said processor (650) to startgathering said phase data at a start time (320), said start time (320)being said predetermined time (320); said A/D converter (640) isconfigured to cause said processor (650) to stop gathering said phasedata at a stop time, said stop time being when a voltage on said lineunder test (610) crosses zero in a predetermined direction; and saidphase data comprises: said start time (320); and a time interval betweensaid start time (320) and said stop time.
 6. An apparatus as claimed inclaim 1 wherein said test phase identification meter (600) additionallycomprises: a timer (655); a receiver (660) configured to receive a timesignal and synchronize said timer (655) to said time signal; and acrystal oscillator (665) configured to track said time signal andsynchronize said timer (655) to said time signal when said receiver(660) is not receiving said time signal.
 7. An apparatus as claimed inclaim 1 wherein said test phase identification meter (600) comprises: ananalog to digital (A/D) converter (640) coupled to said line under test(610); a processor (650) coupled to and configured to control said A/Dconverter (640); a timer (655) coupled to said processor (650) andconfigured to be controlled by said A/D converter (640) through saidprocessor (650); and a GPS receiver (660) coupled to said processor(650), configured to synchronize said timer (655) to a GPS time signal,and configured to establish a start time (320) for said timer (655) whensaid GPS receiver (660) is receiving said GPS time signal.
 8. Anapparatus as claimed in claim 1 wherein: said reference line (150) has aknown phase; said line under test (160) has an unknown phase; and saidcomputer (165) is configured to identify said unknown phase by comparingsaid test phase data to said reference phase data.
 9. An apparatus asclaimed in claim 1 wherein said computer (165) and said reference phaseidentification meter (145) together comprise an integrated unit.
 10. Anapparatus as claimed in claim 1 wherein said first location is within120 miles (193 kilometers) of said second location.
 11. An apparatus asclaimed in claim 1 wherein: said reference phase identification meter(145) and said test phase identification meter (155) receive repetitivetrigger signals; to conduct a single phase test, said reference phaseidentification meter (145) records phase data for each of saidrepetitive trigger signals; and to conduct a single phase test, saidtest phase identification meter (155) records phase data for one of saidrepetitive trigger signals.
 12. An apparatus as claimed in claim 11wherein said phase data contains a trigger-signal identification and aphase interval.
 13. An apparatus as claimed in claim 11 wherein saidtest phase identification meter (155) is configured to record said phasevalues for a plurality of tests prior to establishing communication withsaid computer (165).
 14. An apparatus as claimed in claim 1 wherein:said three-phase power distribution network (100) comprises: a firstphase; a second phase lagging said first phase by 120 degrees; and athird phase lagging said first phase by 240 degrees; said referencephase data comprises a first interval; said test phase data comprises asecond interval; a difference of said first and second intervalscorresponds to an angular displacement; and said phase of said referenceline (150) lags said first phase by 0 degrees.
 15. An apparatus asclaimed in claim 14 wherein: said line under test (160) is asingle-phase secondary output (810,815) coupled to one leg of awye-connected transformer (800); a phase of said one leg is said firstphase when said angular displacement of said line under test (160) isone of 0 degrees and 180 degrees; a phase of said one leg is said secondphase when said angular displacement of said line under test (160) isone of 120 degrees and 300 degrees; and a phase of said one leg is saidthird phase when said angular displacement of said line under test (160)is one of 240 degrees and 60 degrees.
 16. An apparatus as claimed inclaim 14 wherein: said line under test (160) is a single-phase secondaryoutput (910,915) coupled to one leg of a delta-connected transformer;said one leg is coupled between said first and second phases when saidangular displacement of said line under test (160) is one of 150 degreesand 330 degrees; said one leg is coupled between said second and thirdphases when said angular displacement of said line under test (160) isone of 270 degrees and 90 degrees; and said one leg is coupled betweensaid third and first phases when said angular displacement of said lineunder test (160) is one of 30 degrees and 210 degrees.
 17. A method foridentifying a phase of a line in a three-phase power distributionnetwork (100), said method comprising: a) connecting a first phaseidentification meter (145) to a first line (150) at a first point insaid power distribution network (100); b) measuring, with said firstphase identification meter (145), a first interval between a start time(320) and a first stop time; c) connecting a second phase identificationmeter (155) to a second line (160) at a second point in said powerdistribution network (100); d) measuring, with said second phaseidentification meter (155), a second interval between said start time(320) and a second stop time; e) establishing a communication link; f)communicating one of said first and second intervals over saidcommunication link after said measuring activity e); g) computing saidphase of said second line (160) in response to said first and secondintervals.
 18. A method as claimed in claim 17 wherein saidcommunicating activity f) communicates said one of said first and secondintervals to a computer (165).
 19. A method as claimed in claim 17additionally comprising recording said second interval in said secondphase identification meter (155) prior to said communicating activityf).
 20. A method as claimed in claim 19 additionally comprising holdingsaid second interval in said second phase identification meter (155) forgreater than one second prior to said communicating activity f).
 21. Amethod as claimed in claim 19 additionally comprising iterating saidmeasuring activity d) and said recording activity prior to saidcommunicating activity f).
 22. A method as claimed in claim 17 wherein:said method additionally comprises: h) recording said first intervalafter said measuring activity b); i) iterating said measuring activityb) and said recording activity h) a plurality of times; and j) recordingsaid second interval after said measuring activity d); and saidcomputing activity g) computes said phase of said second line (160) inresponse to said recorded second interval and one of said recorded firstintervals.
 23. A method as claimed in claim 22 wherein: said methodadditionally comprises iterating said measuring activity d) and saidrecording activity j); said communicating activity f) communicates saidrecorded second intervals; and said computing activity g) computes, foreach of said recorded second intervals, said phase of said second line(160) in response to said each of said recorded second intervals and oneof said recorded first intervals.
 24. A method as claimed in claim 17wherein: said method additionally comprises: h) recording said firstinterval after said measuring activity b); i) iterating said measuringactivity b) and said recording activity h) a plurality of times togenerate a plurality of said first intervals; j) recording said secondinterval after said measuring activity d); and k) iterating saidmeasuring activity d) and said recording activity j); said communicatingactivity f) communicates said second intervals; and said computingactivity g) computes, for each of said second intervals, said phase ofsaid second line (160) in response to said each of said second intervalsand one of said plurality of first intervals.
 25. A method as claimed inclaim 17 additionally comprising: h) determining, substantiallycoincidentally with said measuring activity b), a first time stamp; i)iterating said measuring activity b) and said determining activity h) aplurality of times to generate a plurality of first phase data, whereineach of said first phase data contains said first time stamp and saidfirst interval; j) recording said plurality of first phase data; and k)maintaining a database of said plurality of first phase data.
 26. Amethod as claimed in claim 25 additionally comprising: l) determining,substantially coincidentally with said measuring activity d), a secondtime stamp; m) producing a second phase data from said second time stampand said second interval; n) recording said second phase data; and o)identifying a match between said second time stamp within said secondphase data and a first time stamp contained within one of said pluralityof first phase data in said database.
 27. A method as claimed in claim17 wherein: said method additionally comprises establishing a data linkbetween said second phase identification meter (155) and a computer(165); and said communicating activity f) communicates said secondinterval to said computer (165) via said data link.
 28. A method asclaimed in claim 17 wherein: said method additionally comprisesestablishing a voice link; and said communicating activity f)communicates said second interval via said voice link.
 29. A method asclaimed in claim 28 wherein said voice link incorporates cellulartelephony.
 30. A method as claimed in claim 17 wherein: said measuringactivity b) measures said first interval between said start time (320)and said first stop time when a voltage on said first line (150) passesthrough a first predetermined voltage in a first predetermineddirection; and said measuring activity d) measures said second intervalbetween said start time (320) and said second stop time when a voltageon said second line (160) passes through a second predetermined voltagein a second predetermined direction.
 31. A method as claimed in claim 17additionally comprising synchronizing said start time (320) in saidfirst and second phase identification meters (145,155) via asatellite-derived time signal.
 32. A method as claimed in claim 17additionally comprising synchronizing said start time (320) in saidfirst and second phase identification meters (145,155) via a time signalof the Global Positioning System.
 33. A method as claimed in claim 17wherein said computing activity g) comprises: establishing as areference phase that phase of said three-phase power distributionnetwork (100) present on said first line (150); establishing as alagging phase that phase of said three-phase power distribution network(100) that lags said reference phase by 120 degrees; establishing as aleading phase that phase of said three-phase power distribution network(100) that leads said reference phase by 120 degrees; establishing as anunknown phase that phase of said three-phase power distribution network(100) present on said second line (160); determining said unknown phaseto be said reference phase when said second interval is substantiallyequal to said first interval; determining said unknown phase to be saidlagging phase when said second interval is longer than said firstinterval by substantially 120 degrees; determining said unknown phase tobe said lagging phase when said second interval is shorter than saidfirst interval by substantially 240 degrees; determining said unknownphase to be said leading phase when said second interval is longer thansaid first interval by substantially 240 degrees; and determining saidunknown phase to be said leading phase when said second interval isshorter than said first interval by substantially 120 degrees.
 34. Amethod as claimed in claim 17 additionally comprising: mapping a servicearea of said power distribution network (100); storing said map withinone of said first and second phase identification meters (145,155); anddetermining if said one of said first and second phase identificationmeters (145,155) is within said service area.
 35. A phase identificationmeter (600) for identifying a line phase in a three-phase powerdistribution network (100), said phase identification meter (600)comprising: an analog to digital (A/D) converter (640) configured togenerate a stop time when an input voltage crosses zero in apredetermined direction; a processor (650) coupled to said A/D converter(640) and said GPS receiver (660), and configured to determine a timeinterval between a start time (320) and said stop time; and a GlobalPositioning System (GPS) receiver (660) configured to generate saidstart time (320) as a predetermined GPS time.
 36. A method foridentifying a phase of a line under test (160) in a three-phase powerdistribution network (100), said method comprising: a) connecting areference phase identification meter (145) to a reference line (150) ata first point in said power distribution network (100); b) connecting atest phase identification meter (155) to said line under test (160) at asecond point in said power distribution network (100); c) measuring,with said reference phase identification meter (145), an instantaneousreference phase of said reference line (150) at a predetermined instantin time; d) measuring, with said test phase identification meter (155),an instantaneous test phase of said line under test (160) at saidpredetermined instant in time; and e) computing said phase of said lineunder test (160) in response to said instantaneous reference phase, saidinstantaneous test phase, and said predetermined instant in time.
 37. Amethod as claimed in claim 36 wherein said predetermined instant in timeis a predetermined Global Positioning System (GPS) time (320).
 38. Amethod as claimed in claim 36 wherein: said measuring activity c)repetitively measures an instantaneous reference phase at each of aseries of predetermined instants in time to produce a plurality of saidinstantaneous reference phases; said measuring activity d) measures saidinstantaneous test phase at said predetermined instant in time, whereinsaid predetermined instant in time is one of said series ofpredetermined instants in time; and said computing activity e) computessaid phase of said line under test (160) in response to one of saidplurality of instantaneous reference phases, said instantaneous testphase, and said one of said series of predetermined instants in time.39. A method as claimed in claim 38 additionally comprising: recordingsaid plurality of instantaneous reference phases in association withsaid series of predetermined instants in time; recording saidinstantaneous test phase in association with said one of said series ofpredetermined instants in time; and communicating said instantaneoustest phase and said one of said series of predetermined instants in timeafter said measuring activity d).
 40. A method as claimed in claim 38wherein said series of predetermined instants in time is a uniformseries of consecutive Global Positioning System (GPS) times (320).